Journal of Applied Research in Chemical-Polymer Engineering

Abstract Research subject: Following the implementation of primary and secondary recovery processes in hydrocarbon reservoirs, enhanced oil recovery (EOR) methods are employed to increase extraction efficiency further. Among the most prominent techniques within this domain is chemical enhanced oil recovery (CEOR), encompassing well-established methods such as polymer flooding, polymer–surfactant hybrid flooding, polymer–nanoparticle flooding, and alkaline–surfactant–polymer (ASP) flooding. Despite their proven efficacy, these conventional approaches are often hindered by high operational costs, technical and operational complexities, and potential environmental concerns. In light of these challenges, polymeric surfactants have recently emerged as a promising and viable alternative, offering the dual functionality of viscosity enhancement and interfacial tension (IFT) reduction in a single agent.
Research approach: This study presents a comprehensive review and critical evaluation of recent research efforts concerning the application of polymeric surfactants in oil recovery processes. Key mechanisms, including viscosity modulation, IFT reduction, and wettability alteration, were systematically analyzed. Furthermore, limitations associated with the synthesis of these materials, elevated production costs, and the fragmented nature of available field data were considered. The review seeks to identify performance trends and knowledge gaps to guide future investigations.
Main results: The findings indicate that, under most reservoir conditions, polymeric surfactants have the potential to significantly improve oil recovery factors. However, their widespread implementation is currently constrained by complex synthesis procedures, economic barriers, and the lack of extensive field validation. This research synthesizes the latest advancements and offers recommendations for future work, including formulation optimization, cost-reduction strategies, and the design of large-scale field trials to assess real-world performance.

Abstract Research subject: Chlorine and its derivatives, due to their unique properties, are used in the production of a wide range of materials in chemical, polymer, agricultural, pharmaceutical, and health industries. In fact, more than half of the marketed products worldwide are directly or indirectly related to the chlorine industry. Given the significance of these chemicals, this study aims to analyze the status of the chlorine chain in Iran’s petrochemical industry and identify its strengths, weaknesses, and investment opportunities.
Research approach: To assess the status of domestic chlorine production, the nominal and actual production capacities of petrochemical companies were collected and analyzed based on official data from the National Petrochemical Company. Using the collected statistics and data, the decrease in the operational rates of petrochemical companies was analyzed. Additionally, the share of end-use applications in the total chlorine consumption in Iran was determined and analyzed using block mass balance of the process units. To identify investment opportunities in the chlorine chain, trade data for chlorine compounds were collected and analyzed based on customs documentation, in order to identify and introduce chemicals with significant import volume or value compared to other substances.
Main results: The results showed that the majority of chlorine in Iran is used for the production of ethylene dichloride/polyvinyl chloride, with this application accounting for over 91% of chlorine consumption in the petrochemical industry. On the other hand, the high cost of replacing mercury-based chlor-alkali units with more environmentally friendly membrane technology and the inability to secure feedstock were identified as the main reasons for the decline in operational capacity for chlorine and polyvinyl chloride production in the country. Using trade statistics, methylene chloride, powder choline chloride, suspension and emulsion polyvinyl chloride, neoprene, and epichlorohydrin were identified as chemicals with high import volume and value, making the evaluation of their production projects important.

Abstract Research subject: Enhanced oil recovery (EOR) is one of the key methods to increase oil recovery from reservoirs, utilizing chemical, physical, or thermal techniques. Among chemical methods, ionic liquids (ILs) have attracted attention as potential alternatives to traditional materials such as surfactants and polymers due to their unique properties, including stability under harsh environmental conditions such as high temperature and salinity, and tunability for specific reservoir conditions.
Research approach: Ionic liquids can serve as surfactant substitutes in enhanced oil recovery processes, but they require proper synthesis and development. Higher environmental sustainability and reduced water consumption are advantages of these materials compared to traditional methods. However, research shows that their impact on EOR performance is relatively limited and requires further optimization, laboratory tests, and simulations. In this article, recent research on the application of ionic liquids in enhanced oil recovery operations is comprehensively reviewed, focusing on their characteristics, mechanisms, experimental results, challenges, and future prospects.
Main results: A review of recent studies shows that ionic liquids can significantly reduce the water/oil interfacial tension and alter the wettability of reservoir rock, both of which are key factors in improving oil transport. For example, the ionic liquid 1-decyl-3-methylimidazolium triflate has shown the ability to reduce interfacial tension significantly. Tests suggest that these materials can recover up to 30% more of the original oil in place.Many ionic liquids also show a strong affinity for asphaltenes and act as solvents and dispersants. This property helps prevent asphaltenes from settling and depositing in the wellbore and around its production zone, which can significantly improve oil flow and production. Ionic liquids can reduce the viscosity of crude oil, making it easier to flow through the reservoir and reducing pressure gradients. However, most studies have been conducted on sandstone reservoirs, and research in carbonate reservoirs is limited, highlighting the need for further investigations.

Abstract Research subject: In recent decades, water and gas injection have gained significant attention for enhancing oil recovery. However, some engineers believe that alternative methods can play a more pivotal role in this field. The use of surfactants is considered an innovative technique that has had a notable impact on the oil industry. Nevertheless, the large-scale production of such materials is financially costly. Additionally, their synthesis results in the generation of toxic and hazardous waste, posing various threats to human health and the environment, ultimately leading to widespread and irreparable pollution. The use of natural surfactants has emerged as a viable solution with relatively high efficiency. These natural surfactants are extracted from the leaves of native plants, offering a cost-effective approach. Moreover, they are biodegradable and pose no risks to human health or the environment.
Research approach: The combination of these natural surfactants in oil-related experiments has yielded satisfactory results, demonstrating their effectiveness in reducing interfacial tension between water and oil, as well as modifying the viscosity of crude oil. This study specifically examined the interaction between surfactants and divalent ions at their lowest concentrations. One of the testing processes involved injecting these solutions into a micromodel, which was subsequently analyzed.
Main results: The combination of these surfactants with divalent ions and crude oil significantly reduced interfacial tension. Notably, the combination of Morus leaf extract with calcium ions reduced the interfacial tension of crude oil to 15.6 mN/m, while Citrus extract with sulfate ions reduced it to 13.6 mN/m. Additionally, in many viscosity tests, a reduction in crude oil viscosity was observed. The combination of calcium ions with Morus extract resulted in approximately 41% oil recovery, whereas sulfate ions with Citrus extract led to a 50% final recovery rate.

Abstract Research subject: Multi-level leakage modeling in horizontal and inclined pipelines using real-time sensor data analysis
Research approach: The environmental severity of oil pipeline leakage depends on the leak volume, which is directly related to the time required for leak detection and containment. The use of real-time sensors installed at multiple locations along the pipeline facilitates effective leak detection through continuous data collection. Leak detection simulation for repair planning is a critical factor in pipeline design, implementation, and evaluation. This study proposes a framework for generating pipeline datasets using PipeSim software and Python’s random function. A horizontal–inclined pipeline configuration was initially analyzed, and pressure profiles under leak and non-leak conditions were evaluated. Subsequently, leak analysis was conducted on an inclined pipeline with a slope angle of 20 degrees. Because leakage alters the pressure profile, pressure variations were used as inputs to a machine learning algorithm, and the pressure distribution along the pipeline was simulated accordingly.
Main results: Before leakage, the local pressure drop at the leak point was 1270 psi in the horizontal–inclined pipeline and 792 psi in the inclined pipeline. After leakage, the minimum pressure dropped to 800 psi in the horizontal–inclined pipeline and 500 psi in the inclined pipeline. These results indicate a greater pressure drop reduction at the leak point in the horizontal–inclined pipeline (470 psi) compared to the inclined pipeline. This behavior is attributed to the higher flow velocity induced by gravity in the inclined pipeline, which mitigates severe pressure drops at the leak location. Consequently, leak severity decreases under conditions of high flow velocity and lower pressure reduction.

Abstract Research topic:

The disparity between supply and demand is one of the main obstacles in transitioning from fossil fuels to renewable energy. Underground hydrogen storage derived from renewable sources is a suitable method for storing energy from these sources. However, a portion of the stored gas remains in the reservoir as cushion gas, which can add to the operational costs. It is therefore recommended to replace this cushion gas with less expensive alternatives, such as CO₂ or sour gas, to reduce these costs. Nevertheless, this replacement can affect the purity and recovery factor of hydrogen, which can be controlled by specific operating parameters. This study will investigate how these parameters can be adjusted to maintain high purity and recovery factor for stored hydrogen.

Research Method:

In this section, a model of a partially depleted gas reservoir was initially constructed using the commercial simulator CMG. Following validation, this model was employed to evaluate the desired parameters. For this purpose, approximately 50% of the reservoir was depleted initially, followed by the injection of the cushion gas for one year. Subsequently, the hydrogen storage process was conducted over a period of 10 years. This research investigates the impact of various parameters, including the duration and rate of hydrogen injection and production, the soaking time and duration of cushion gas injection, the utilization of sour gas as the cushion gas, and the concentration of H₂S within it, on the purity and recovery factor of the produced hydrogen.

Main results:

The results showed that increasing the rate of hydrogen injection and production enhances its purity and recovery factor. Reducing the injection period while increasing the extraction period decreases purity but improves recovery, provided that the extraction period does not exceed the injection period. Extending the cushion gas injection time and the interval between injection and hydrogen storage supports the purity and recovery factor of hydrogen. Additionally, in the cushion gas composition, increasing the proportion of H₂S above 70% in the sour gas mixture reduces hydrogen purity and recovery by approximately 2% and 3%, respectively, confirming the potential of H₂S as a cushion gas.

Abstract Research Subject:Drilling operations frequently encounter numerous challenges that can lead to significant financial, human, and environmental losses. Therefore, predicting potential problems before they occur and implementing necessary preventive measures is crucial to minimizing risks. In this context, this study investigates the impact of employing artificial intelligence (AI) algorithms to forecast drilling complications using real-time mud logging data collected from existing wells in an Iranian oilfield.

Research approach: A hybrid architecture combining Long Short-Term Memory (LSTM) and Fully Connected neural networks was developed for the identification and detection of anomalies such as kicks and stuck pipe. Given the scarcity of these anomalies in the dataset, which could adversely affect model accuracy and performance, the Synthetic Minority Oversampling Technique (SMOTE) was applied to balance class distribution and enhance the overall effectiveness of the network. Furthermore, the influence of varying hyperparameters on reducing network error was systematically analyzed.

Main Results: Various network architectures and structures were examined. The experimental results indicated that the optimal model achieved an accuracy of 94.45% on the testing dataset with the following hyperparameters: a lookback of 7, a learning rate of 0.001, a dropout rate of 0.2, a batch size of 32, and a four-layer network architecture with 512, 256, and 256 units in the first, second, and third hidden layers, respectively. This configuration yielded higher accuracy and fewer false alarms in anomaly detection compared to other tested models. Based on the obtained results, this approach demonstrates significant potential for real-time anomaly detection in drilling operations.

Abstract Research subject: Using microwave and ultrasonic waves is a novel method in the petroleum industry that has been investigated for various purposes. Due to polar elements such as oxygen, nitrogen, and sulfur, oil molecules are affected by the electric field of microwave waves and create dipole moments that generate hotspots, increasing the temperature of the oil and breaking down heavy compounds such as asphaltene. Ultrasonic waves eliminate intermolecular forces by creating tiny bubbles and bursting them. It also leads to the breakdown of heavy molecules such as asphaltene.
Research approach: In this study, crude oil was exposed to microwave and ultrasonic radiation, and changes in its properties were investigated. The effects of changing parameters such as power and time on crude oil properties were also examined. Changes in the specific gravity and API can indicate the extent of the breakdown of heavy molecules such as asphaltene and improvement in crude oil quality.
Main results: Using microwave and ultrasonic waves can reduce the viscosity of crude oil by 12.4% and 6% and increase the API by 2.8 and 1.2 degrees, respectively. Asphaltene reduction due to microwave and ultrasonic waves is 9.3% and 4.3%, respectively, indicating the breakdown of these compounds and the conversion to smaller compounds soluble in oil, resulting in improved crude oil quality. The EDS results show an increase in the weight percentage of carbon and the reduction of elements such as oxygen and sulfur, which confirms this issue. Examining crude oil structure under microwave and ultrasonic radiation showed that microwave waves, in addition to affecting straight-chain hydrocarbons, also reduced aromatic compounds. However, ultrasonic waves had a more significant effect on straight-chain hydrocarbon structure.

Abstract One of the problems related to oil recovery is water production, which reduces the production life of oil reservoirs and wells. Nowadays, the polymer gel injection method is used to control water production in the reservoir. In this study, an attempt has been made to investigate the rheological properties of xanthan-based hydrogels, considering Iran's reservoirs and also due to the existence of environmental problems in the field of synthetic polymers. The strength and stability of hydrogels can be applied by changing environmental conditions as a function of time and shear rate. For this purpose, the viscoelastic properties of hydrogels, including the elastic and viscous modulus, have been studied in relation to temperature, time and deformation rate for the gelant solution. Also, the effect of the composition of hydrogels, including the polymer concentration, the weight ratio of the crosslinking agent to the polymer, and the weight percentage of silica nanoparticles was considered in the study of rheological properties. Additionally, gelation time has been studied as one of the most important determining parameters of hydrogel during injection in porous medium.

Abstract Research topic:
Gas lift is an efficient artificial lift strategy, routinely used to overcome the low productivity of the wells. In this research, the possibility of using two gases, carbon dioxide and nitrogen instead of natural gas, in the gas lifting process is investigated and compared. To maximize oil production, the optimization of the allocation of the limited amount of gas between 10 wells in the Iranian offshore brown oil field is performed.
Research Method:
In this research, all the wells were modeled by PROSPER software. First, all 10 wells data of an Iranian offshore oil reservoir were collected. Secondly, their model has been built and after validation, a simulation of the artificial gas lift was performed using carbon dioxide and nitrogen gas separately, then, the Gas Lift Performance Curve (GLPC) of all the wells are fitted with the appropriate experimental model in MATLAB software. In the following, using Solver Excel, the allocation optimization with a limited amount of gas was performed using two different gases.
Main results:
According to the results obtained from the optimization, for a certain amount of available gas which is 15 MMSCFD, the total Oil production in the case of nitrogen gas injection is 3564 STBD more than carbon dioxide gas injection. Also, in all cases, due to the production potential capacity of well No. 8, the most amount of injected gas is allocated to it. The comparison of the two types of injected gas shows that the quantity of oil produced using nitrogen is 3424 and 3302 STBD (28 % and 24 %) greater than carbon dioxide gas when the gas is lowered to 12 and 9 MMSCFD, respectively.

Abstract Research Subject: In recent years, smart water flooding has gained attention regarding enhanced oil recovery, and one of its driving mechanisms is wettability alteration. However, the effect of acid presence on smart water performance needs to be clarified. Thus, the main question is whether the presence of acid and potential determining ions can lead to further wettability alteration and interfacial tension (IFT) reduction. Additionally, in this study, trivalent cations were added to smart water for the first time, and the results were compared with those of divalent cations.
Research approach: In this study, seawater (SW), 4-times diluted SW, and 8-times diluted SW were prepared in distilled water, 0.001 normal HCl and 0.01 normal HCl, and the contact angle and IFT experiments were carried out. In addition, concentrations of Ca²⁺, Mg²⁺, and Fe³⁺ were adjusted in 8-times diluted SW prepared in 0.01 normal HCl, and the IFT and contact angle tests were conducted.
Main Results: The results showed that the presence of acid in distilled water could decrease the IFT values; however, it did have a marginal effect on contact angle reduction. Also, because of synergistic effects between acid and potential determining ions, IFT significantly declined. While adding acid to brines with different salinities resulted in contact angle reduction, the glass surface remained oil-wet. Regarding divalent and trivalent cations, the results revealed that increasing Fe³⁺ concentration in smart water made the glass surface water-wet. However, adjusting Ca²⁺ and Mg²⁺ concentrations changed the wettability from oil-wet to neutral-wet. Moreover, divalent and trivalent cations showed similar behavior in IFT reduction, and a four-times increase in the concentration of each mentioned ion reduced IFT by about 2 mN/m.

Abstract Research subject: Investigation of the effect of temperature on the polymer flooding performance at the pore scale, leads to an understanding of the behavior of the polymer solution in porous media with varying permeability.
Research approach: In this study, the effect of temperature on flooding of polyacrylamide polymer on enhanced oil recovery in two homogeneous micromodels at 25 and 70 °C was investigated. The polymer solution and DW were injected at the injection rate of 1 μl/min up to 1 PV into the micromodel and the amount of produced oil and the movement of the injected fluid in the porous medium were analyzed. In addition, polymer rheology and injected fluid viscosity were measured for better analysis of results. Then the results were compared with flooding of distilled water as the control test.
Main results: Examining the flood results, it was found that on the one hand, the temperature factor helped to increase oil recovery by reducing the viscosity of the oil. On the other hand, it has reduced the role of injected fluid viscosity in oil extraction by reducing the viscosity of the polymer. The results showed that the phenomenon of fingering decreases in the case of polymer injection, and the rate of improvement of oil recovery during polymer and water flooding in both micromodels increases with increasing temperature. Also, the rate of improvement of oil recovery during polymer flooding in the A micromodel increased from about 43% at ambient temperature to more than 51% and in the B micromodel from about 51% to more than 60% at 70 °C. In fact, it can be said that the flow pattern and stability of the polymer solution front and consequently the ultimate oil recovery are significantly affected by the morphology of the pores, the shape and the throats pores.

Abstract موضوع تحقیق: یکی از روش­های نوین در فرآیندهای افزایش بازیافت نفت از مخازن هیدروکربوری، بکارگیری امواج اولتراسونیک میباشد. در این تحقیق با استفاده از امواج اولتراسونیک و اعمال آن در یک مخزن نمونه مقیاس بزرگ، به بررسی اثر آن در ازدیاد برداشت نفت به روش عددی پرداخته شده است.
روش تحقیق: در این تحقیق فرایند مدلسازی با استفاده از نرم افزار متلب انجام شده است. ابتدا با تعیین محیط متخلخل میزان افزایش فشار حاصل از موج اولتراسونیک با توجه به حل معادلات صوت ( هلمهولتز) توسط جعبه ابزار k-waves متلب بررسی شده و سپس با تعیین مخزن نمونه و حل معادلات حاکم بر مخزن میزان تغییرات فشار حاصل از جریان سیال در حضور چاه تولیدی به بررسی اثر موج اولتراسونیک در ازدیاد برداشت نفت پرداخته میشود. در نهایت با توجه به تولید تجمعی در یک زمان مشخص از چاه تولیدی و تعیین بازیافت نفت از مخزن در حضور موج، به بررسی اثر پارامترهای موقعیت مکانی چاه و فاصله آن از منبع تولید موج، زمان شروع تولید موج، شیوه­ای اعمال موج (پالسی و پیوسته)، در یک فرکانس و توان بهینه پرداخته میشود.
نتایج اصلی: با توجه به نتایج بدست آمده از مدلسازی، هرچقدر زمان شروع اعمال موج به روزهای اول تولید نزدیک­تر باشد، میزان بازیافت نفت نیز بیشتر میشود؛ به گونه ای که با شروع اعمال موج اولتراسونیک تحت توان 5 کیلووات و فرکانس 20 کیلوهرتز همزمان با تولید نفت چاه از روز اول، بازیافت نفت نسبت به بازیافت نفت در حالتی که شروع اعمال موج از روزهای پنجاه و نود باشد، به ترتیب %5/4 و %8 بیشتر شده است. بازیافت نفت درصورتی که موج در یک زمان مشخص بصورت پیوسته به مخزن اعمال شود به میزان 8/1% نسبت به حالتی که در همان زمان بصورت پالسی اعمال شود، بیشتر است .نتایج مدلسازی نشان میدهد که هرچقدر فاصله منبع تولید موج با چاه تولیدی کمتر باشد، افت فشار محدوده چاه کمتر شده و بازیافت نفت افزایش میابد. بطوری که طبق نتایج اگر منبع تولید موج در فاصله 200 فوتی از چاه تولیدی قرار گرفته باشد، نسبت به فاصله 1800 فوتی از چاه بازیافت نفت % 1/7 افزایش میابد.

Abstract Research subject: In situ synthesis of nanoparticles due to greater impact on production mechanisms (such as reducing oil viscosity), uniform distribution of nanoparticles in reservoir fluids, no reduction in formation permeability due to no injection of nanofluids into the reservoir and also economic efficiency is more importance than other nanoparticle synthesis methods which are used in enhanced oil recovery (EOR) processes.
Research approach: In this study, the effect of in-situ synthesized of cerium oxide (CeO₂) nanoparticles at low temperature on the oil recovery factor was investigated. For this purpose, water was considered as the based fluid for dispersion of synthesized nanoparticles. Also, in order to study the effect of nanoparticles concentration in the base fluid on the final oil recovery factor, several nanofluids were prepared at different concentrations of 0.01, 0.1, 0.25 and 0.5 wt.%. Finally, the prepared nanofluids were injected at the injection rate of 0.07 ml/h up to 1 PV into the micromodel and the amount of produced oil and the movement of the injected fluid in the porous medium were analyzed.
Main results: The results showed that the synthesized CeO₂ nanoparticles in this study have appropriate performance to improve the oil recovery factor. The presence of small amounts of these nanoparticles (concentration of 0.01 wt. %), causes a significant increment in oil recovery factor (about 7%) compared to water injection alone. Also, the oil extraction coefficient increased by increasing the concentration of nanoparticles in the base fluid. So that for nanofluids with concentrations of 0.01, 0.1, 0.25 and 0.5 wt.%, the oil recovery factor were 25%, 38%, 43% and 45%, respectively. However, by increasing the concentration of nanoparticles in the base fluid, from an optimal amount onwards, the probability of particle deposition in the micromodel increased, the effect of nanoparticles on changing the hydrodynamic properties of the injected fluid and oil production mechanisms decreased.

Abstract Research subject: Prediction of the wellbore temperature during the downhole operations and its effects on the stress condition of the tubulars is one of the important factors in design of the completion, production and stimulation operations in oil and gas wells. Temperature changes during the life of the well can change the stress condition of the pipes inside the well, such as the tubing and the casing, and cause problems such as wellhead displacement or buckling of the tubulars, which is dangerous in both terms of safety of the well and personnel and it can also be economically inefficient.
Research approach: In this study, various operations during the life of a well such as running the completion string, production start-up, the well shut in, acid injection and other common operations in oil wells were simulated in a practical order. Temperature changes during these operations and their effect on the stress condition of the wellbore casing and tubing were investigated.
Main results: The results showed that long-term production of the well causes the most temperature changes in the well. This increase in the temperature reached a maximum value at a depth of 430 ft, which is the mud line depth. Further, because the pipe is fixed, it buckles and creates torque at deeper well depths. The results also showed that the time required for the temperature to be completely stable is about a few months, and this should be taken into account in the tubing pressure test analysis.

Abstract Research subject: Mazut is widely used in petrochemical, power, and marine industries. The use of these fuels, in addition to causing widespread air and sea pollution in the country, has also led to severe international penalties, rising costs, and corrosion of equipment. Therefore, the use of mazut fuel with sulfur compounds of up to 0.5% in the world, as a refining mazut fuel at the origin (in refineries) and taking into account all aspects, is more important. There are limited industrial methods for the hydrotreating of mazut (Due to the heavy oil cut and the complexity of sulfur compounds in it), the most common of which is hydrogen desulfurization (HDS).
Research approach: The goal of this research, The simulation and economic evaluation of the hydrotreating plant from Mazut fuel with a capacity of 13.75 million barrels per year. The simulation of this process was performed in Aspen HYSYS petroleum refinery software. In this simulation, the effect of effective operating parameters such as pressure, hydrogen to mazut ratio, and finally catalyst consumption on the removal of sulfur compounds, production of by-products, net production costs, and total investment costs are investigated.
Main Results: The results showed that for the hydrotreating process of this mazut with sulfur compounds 3.5%, total capital investment is 308.9 million US$ and the net production cost of treated mazut fuel is estimated to be 114.5 million US$ per year. Also, economic sensitivity analysis showed that the operating parameter of the hydrogen to mazut ratio had the greatest effect on increasing the total capital investment and net production cost, which should be minimized as much as possible.

Abstract Research Subject: Global energy demand is increasing, so enhanced oil recovery techniques have incorporated in production processes. Water flooding is a common technique in oil recovery processes. One of the major challenges in this technique is heterogeneity of the reservoir structure which results in increased water production and reducing the oil recovery factor. Moreover, long-term water or chemical injection might lead to the increased horizontal and vertical heterogeneities in the reservoir. Selective blockage of high permeability areas and consequently improved production from low permeability regions is important for increasing the oil recovery factor. In recent years, using hydrogels in injection processes, has been associated with various field successes, indicating the ability of these materials for selectively blocking the areas of high permeability. Hydrogels are injected after water or polymer flooding to conduct the injected fluid to low permeability areas.
Research Approach: In this paper, hydrogel injection process was simulated in glass micromodels using Comsol Multiphysics software. Hydrogel functionality was studied in low permeability areas in porous media. Moreover, the optimized conditions for water flooding process was studies. For this purpose, after model validation, sensitivity analysis was performed on effective parameters on oil recovery factor and a mathematical model was presented to predict the oil recovery factor.
Main Results: Oil recovery factors obtained from experimental and simulation studies, were in good agreement with each other with absolute error values of 2.29% and 4.06%, for water and hydrogel flooding, respectively.
Four parameters of injection rate, contact angle, oil viscosity, and injection fluid viscosity were considered as effective parameters on oil recovery factor. Among them, contact angle was the most important parameter. In water flooding, the most important interacting parameters are viscosity and contact angle and the least important parameters are injection temperature and rate. In water flooding simulation studies, the thickness of the contact surface was obtained hmax/5, where is 230 micrometers. For hydrogel injection, the contact surface thickness was obtained terpf.ep_default / 5.65. Terpf.ep_default is the thickness of contact surface, equal to 631 micrometers

Abstract In this research, the possibility of asphaltene separation from the vacuum tower residue using the low cost industrial solvents such as 402, 404, 406, and 410 was investigated. In order to separate asphaltene the IP143/01 and ASTM D 3279-07 separation methods were utilized. In order to find the optimal state of asphaltene precipitation, Design of experiments software with three factors of residence time, the solvent-to-feed ratio and the volume percent of 406 solvent to the total solvent of 406 and 410 were used. The results showed that the effectiveness of each parameter in precipitating the asphaltene attributed to the ratio of solvent to feed, the ratio of solvent 406 to total solvent, and the residence time, respectively and there was a significant interaction between the basic parameters. The best asphaltene precipitation of 5.06% of 7.5% happens at the residence time of 36.97 hours, the ratio of solvent to feed of 35.95 ml/gr and the volume percent of 406 solvent to the total solvent of 27.20%. Asphaltene precipitation percentage for the optimal mixture of industrial solvents was 22.5% lower than the precipitated asphaltene from normal heptane solvent. However, according to the solvents price, industrial solvents (410 and 406) were approximately 50% cheaper than normal heptane, and hence on overall, there was a cost savings of more than 20%

Abstract Abstract:
Research subject: In water injection process, part of the surface active agents that are naturally present in oil can be dissolved in injected water. The presence of these substances affects the surface phenomena of the three phase water-oil-rock system. The effect of these substances on modification of the ionic composition of injected water has been less investigated in previous studies.
Research approach: In this paper, first, the effects of acidic compounds in crude oil and connate water composition on initial wettability of carbonate rock were investigated. Then to investigate the wettability changes of oil-wet calcite rock, single-salt aqueous solutions of MgCl₂, CaCl₂, KCl, and Na₂SO₄ having concentrations of 0.1 to 1 molar were used.
Oil–water interfacial tension (IFT) for distilled water and salt waters in various concentrations were measured and compared. Variations of calcite rock surface properties were investigated by contact angle measurement after aging of thin sections in oil and salt waters.
Main results: Results indicated that by increasing ion concentration and ionic strength of salt waters, IFT decreases due to dissolution of acidic compounds of oil at the interface of oil and water. Moreover, for high content of acidic compounds in the oil, Magnesium ion has the most impact on reducing IFT and altering the rock wettability. So that by increasing the concentration up to 1 molar, IFT and contact angle decrease to 1 mN/m and 42 degrees, respectively.
Contact angle measurements revealed that the composition of connate water is effective in changing the initial wettability of the rock, and formation of ionic-organic layer adjacent to the rock surface is one of the most important factors in wettability alteration. The presence of Magnesium ion in connate water decreases the contact angle to 145 degrees and causes the rock surface to become more water wet.
Also, increasing solubility of oil-soluble acidic compounds in the aqueous phase has a significant effect on the rock wettability. The experimental results showed that the interaction between ions in the aqueous phase, especially the divalent ions, and surface active agents (carboxylic acid) determine the surface behavior of water in contact with oil and rock.

Keywords: Wettability, IFT, Acidic oil, Divalent ions, Ionic-organic layer

Abstract In the present study, the agglomeration and fragmentation of asphaltene particles have been simulated in laminar using the simultaneous coupling of Discrete Element method and Computational Fluid Dynamics. A new coalescence model according to the nature of asphaltene has been proposed. Asphaltene flocs have been considered as irregular shape rigid object. Particle collisions and collision efficiency as well as the fragmentation of asphaltene flocs have been studied in details. Furthermore, the asphaltene particles growth and change in particle size distribution along with average fractal dimension changes have been investigated. During the flocculation of the asphaltene particles, the asphaltene particles grow slowly in the initial times. It can be explained by the agglomeration of primary particles and the formation of asphaltene flocs. In the middle time period, due to the collision of the flocs and the formation of large flocs, the growth of the asphaltene particles increase. At the late times, the fragmentations limit the floc growth, and eventually asphaltene particle size approximately reaches a constant value in the steady state. The lognormal distribution provides the best fit for the asphaltene PSDs which, according to previous studies, is also consistent with the nature of asphaltene. The results of proposed collision and fragmentation kernels based on simulation results are agreed well with previous studies.

Abstract Research subject: Regarding to temperature effect on the rate of corrosion in absorption tower of gas refineries, it is very useful to examine and invest on new methods to decrease the temperature in mentioned towers.
Research approach: By studying different types of corrosion in amine processes and the influence of different variables on them, the dominant effect of temperature on the rate of corrosion in absorption towers was determined. Due to decreasing temperature in the absorption tower the surface tension of amine solvent and corrosion rate decrease. The reduction in surface tension reduces the foaming and flooding in the tower, which reduces the concentration of sour gases CO₂ and H₂S from the natural gas outlet. Various methods of reducing temperature in the absorption tower such as increasing flow rate of circulation amine solvent, opening the insulated tower wall and injecting amines into the middle of the tower have been studied. Aspen- HYSYS software was used to investigate the effects of amine injection into the middle of the tower.
Main result: According to the simulation results, the maximum temperature in the two-feed absorption tower was reduced to about 3°C and in the three feedstocks the maximum temperature was reduced to about 10°C. Also, as the CO₂ and H₂S concentration of the gas outlet decreases, the amount of Spent Caustic and catalyst in the lower part of the tower will decrease. Finally, it was found that among the above methods, injection of amine into the middle of the tower had the highest efficiency in decreasing the temperature of it. However, a combination of the above methods can be used to further reduce the temperature in the tower.

Abstract Research subject: Methane hydrate reservoirs as an unconventional resource of natural gas can secure demand of energy in the world for many years. Efficient production prom this resources is the subject of concern. CO₂-Methane replacement is a novel method for production from naturally occurring methane hydrate deposits such that methane production and CO₂ storage take occur simultaneously. Research approach: In this study a new kinetic model is proposed for CO₂-Methane replacement in hydrate structure. This kinetic model is developed based on the mechanism proposed for replacement in the hydrate structure in the presence of excess water in a slurry phase of methane hydrate. According to this mechanism partial breakage of methane hydrate cages, methane-CO₂ substitution and formation of CO₂ hydrate proceed simultaneously. Methane hydrate dissociation and CO₂ hydrate formation kinetic parameters are evaluated experimentally and fitted on polynomials as function of pressure and temperature. Main results: Evaluation of the effects of pressure and temperature on the replacement efficiency show that higher replacement efficiency is obtained at higher temperatures and lower pressures. It means that replacement kinetic is controlled by methane hydrate dissociation step. Since, higher temperature and lower pressure favor dissociation of methane hydrate. At 278.15 K the replacement efficiency decreased from 15.78 to 8.80 as total pressure increased from 55 bar to 65 bar, at 280.15 K it decreased from 26.98 to 15.91 by decreasing total pressure from 60 bar to 70 bar. At same pressure 60 bar for 280.15 K and 278.15 K the replacement efficiency is 20.96 and 11.59 respectively.

Abstract Propane and butane that are the contents of LPG are separated from natural gas in the unit 107 of 5^th refinery of South Pars Gas Company (SPGC). The concentration of methyl mercaptan and ethyl mercaptan in the propane stream are 551 and 46ppm, respectively, and the concentration of these components in butane stream are 1218 ppm and 0.8%, respectively. In order to remove mercaptans from butane and propane, aqueous solution of sodium hydroxide with 15 to 20% wt. is used for the scrubbing. In this research, using the Petro-SIM software, which is a particular simulator for oil and gas industries, the units 113, 114, and 115 of 5^th refinery of SPGC are simulated. The results of the simulation are compared with the data of both experimental data and design documents, and they are goodly match. Then, using the software optimizer the operating parameters is optimized. The optimization results show that by increasing the extraction temperature in the unit of 115 up to 46 ° C, the concentration of mercaptan in the products can be reduced. The other independent parameters do not affect the final result of the process.

Abstract In order to develop the scope of application of polymer materials in the preparation of drilling fluids, in this study, various blends of wheat starch and copolymer of sulfonated polyacrylamide were prepared and the rheology and compatibility behavior of samples under different salinity and aging conditions were evaluated. The rheological behavior of starch-polyacrylamide blends in tap water and saturated brine water showed that the viscosity of the samples increased with increasing concentration of polyacrylamide copolymer in the both media. However, starch-polyacrylamide blends in saturated brine had less viscosity than tap water. It was observed that in both tap water and salt water saturated conditions after 4 hours of aging at 90 ° C, the viscosity of most samples increased. Comparison of the curves for empirical viscosity data and prediction of the mixing rule showed that in both of tap water and salt saturated water, positive deviation from the mixing rule is observed, which indicates the compatibility between the blend components. By performing the aging process, although positive deviation was still observed, this positive deviation slightly decreased, which means the negative effect of aging on the compatibility of the starch- copolymer of sulfonated polyacrylamide blend.
In conclusion, the results of this study showed that the blend of starch- sulfonated polyacrylamide copolymer is compatible at high temperature (90 °C) and saturated NaCl salt wate. Moreover, in some samples, this compatibility exists even after aging.

Abstract one of the most common improved oil recovery method in the world. High residual oil saturation at the end of this method is due to low macroscopic sweep efficiency and viscous fingering. It can be improved by the mobility control during polymer solution injection. In this study, by of silica/ the effect of it on IFT, viscosity, and was investigated. In addition, the performance of in high salinity water was studied by using nano particles. The zeta potential results show that the stability of polymer solution was enhanced in of nano particles in high salinity water condition. Also, the lowest IFT was obtained for contained 1 percent nano silica (18.34 ), and the most tendency to water wet conditions was provided for this concentration. In addition to, 1 percent nano silica/ has the best performance on formation water viscosity and improved the mobility ratio to 1.07, which it can increase the oil recovery.